(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or
for such shorter period that the registrant was required to file such reports) and (2) has been
subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files).

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer o

Accelerated Filer þ

Non-Accelerated Filer o(Do not check if a smaller reporting company)

Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).

Yes o No þ

At
November 7, 2011, 78,809,515 shares of the Registrants Common Stock were outstanding.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, ORGANIZATION AND BASIS OF
PRESENTATION

1.

Basis of Financial Statements

The accompanying unaudited condensed consolidated financial statements present the financial
position at September 30, 2011 and December 31, 2010 and the results of operations for the three
and nine month periods ended September 30, 2011 and 2010, and cash flows for the nine month periods
ended September 30, 2011 and 2010 of RAM Energy Resources, Inc. and its subsidiaries (the
Company). These condensed consolidated financial statements include all adjustments, consisting
of normal and recurring adjustments, which, in the opinion of management, are necessary for a fair
presentation of the financial position and the results of operations for the indicated periods. The
results of operations for the three and nine months ended September 30, 2011 are not necessarily
indicative of the results to be expected for the full year ending December 31, 2011. Reference is
made to the Companys consolidated financial statements for the year ended December 31, 2010
included in the Companys Annual Report on Form 10-K, for an expanded discussion of the Companys
financial disclosures and accounting policies.

2.

Nature of Operations and Organization

The Company operates exclusively in the upstream segment of the oil and natural gas industry
with activities including the drilling, completion, and operation of oil and natural gas wells. The
Company conducts the majority of its operations in the states of Texas, Oklahoma and Louisiana.
The Company also owns and operates oil and natural gas properties in New Mexico, Mississippi and
West Virginia.

3.

Use of Estimates

The preparation of financial statements in conformity with accounting principles, generally
accepted in the United States of America, requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those estimates. Estimates
and assumptions that, in the opinion of management of the Company, are significant include oil and
natural gas reserves, amortization relating to oil and natural gas properties, asset retirement
obligations, derivative instrument valuations and income taxes. The Company evaluates its estimates
and assumptions on a regular basis. Estimates are based on historical experience and various other
assumptions that are believed to be reasonable under the circumstances, the results of which form
the basis for making judgments about the carrying values of assets and liabilities that are not
readily apparent from other sources. Actual results may differ from these estimates used in
preparation of the Companys financial statements. In addition, alternatives can exist among
various accounting methods. In such cases, the choice of accounting method can have a significant
impact on reported amounts.

4.

Income per Common Share

Basic and diluted income per share is computed by dividing net income by the weighted average
number of common shares outstanding for the period. A reconciliation of net income and weighted
average shares used in computing basic and diluted net income per share are as follows (in
thousands, except share and per share amounts):

The Company evaluates events and transactions that occur after the balance sheet date but
before the financial statements are filed with the U.S. Securities and Exchange Commission (SEC).

B 

PROPERTIES AND EQUIPMENT

Under the full cost method of accounting, the net book value of oil and natural gas
properties, less related deferred income taxes, may not exceed the estimated after-tax future net
revenues from proved oil and natural gas properties, discounted at 10% (the Ceiling Limitation).
In arriving at estimated future net revenues, estimated lease operating expenses, development
costs, and certain production-related and ad valorem taxes are deducted. In calculating future net
revenues, prices and costs are held constant indefinitely, except for changes that are fixed and
determinable by existing contracts. The net book value is compared to the Ceiling Limitation on a
quarterly and yearly basis. The excess, if any, of the net book value above the Ceiling Limitation
is charged to expense in the period in which it occurs and is not subsequently reinstated. At
September 30, 2011 and 2010, the net book value of the Companys oil and natural gas properties did
not exceed the Ceiling Limitation.

C 

LONG-TERM DEBT

Long-term debt consists of the following (in thousands):

September 30,

December 31,

2011

2010

Credit facilities

$

200,000

$

196,521

Accrued payment-in-kind interest

-

221

Installment loan agreements

398

350

200,398

197,092

Less amount due within one year

146

127

$

200,252

$

196,965

Credit Facilities

In
March 2011, the Company entered into new credit facilities. The
new credit facilities, which
replaced the Companys previous credit facility, include a $250.0 million first lien revolving
credit facility and a $75.0 million second lien term loan facility. SunTrust Bank is the
administrative agent for the revolving credit facility, and Guggenheim Corporate Funding LLC is the
administrative agent for the term loan facility. The borrowing base under the revolving credit
facility at September 30, 2011 was $150.0 million. The borrowing base is reviewed and redetermined
effective March 31 and September 30 of each year, and between scheduled redeterminations upon
request. On September 30, 2011, the borrowing base was reaffirmed at $150.0 million based on the
value of the Companys proved reserves at June 30, 2011. Funds advanced under the revolving credit
facility may be paid down and re-borrowed during the five-year term of the revolver, and bear
interest at LIBOR plus a margin ranging from 2.5% to 3.25% based on a percentage of usage. The
term loan credit facility provides for payments of interest only during its 5.5-year term, with the
interest rate being LIBOR plus 9.0% with a 2.0% LIBOR floor, or if in any period the Company elects
to pay a portion of the interest under its term loan in
kind, then the interest rate will be LIBOR plus 10.0% with a 2.0% LIBOR floor,

and with 7.0% of the interest amount
paid in cash and the remaining 3.0% paid in kind by being added to the principal. At September 30,
2011, $125.0 million was outstanding under the revolving credit facility
and $75.0 million was outstanding under the term loan credit facility.

Advances under the new credit facilities are secured by liens on substantially all properties
and assets of the Company and its subsidiaries. The new credit facilities contain representations,
warranties and covenants customary in transactions of this nature, including restrictions on the
payment of dividends on the Companys capital stock and financial covenants relating to current
ratio, minimum interest coverage ratio, maximum leverage ratio and a required ratio of asset value
to indebtedness. The Company was in compliance with all of its
covenants in the new credit facilities
at September 30, 2011. The Company is required to maintain commodity hedges on a rolling basis for
the first 12 months of not less than 60%, but not more than 85%, and for the next 18 months of not
less than 50%, but not more than 85%, of projected quarterly production volumes, until the leverage
ratio is less than or equal to 1.5 to 1.0. During June 2011, the Company entered into the First
Amendment to the revolving credit facility. The First Amendment amended certain definitions
affecting covenant calculations and modified the terms of the Companys natural gas derivative
counterparty requirements.

The Companys previous credit facility entered into in November 2007, included a $500.0
million credit facility with Guggenheim Corporate Funding, LLC, for itself and on behalf of other
institutional lenders. The previous credit facility included a $250.0 million revolving credit
facility and a $200.0 million term loan facility and an additional $50.0 million available under
the term loan as requested by the Company and approved by the lenders. The initial amount of the
$200.0 million term loan was advanced at closing. Funds advanced under the previous revolving
credit facility initially bore interest at LIBOR plus a margin ranging from 1.25% to 2.0% based on
a percentage of usage. The previous term loan provided for payments of interest only during its
term, with the initial interest rate being LIBOR plus 7.5%. The borrowing base under the previous
revolving credit facility was $145.0 million at December 31, 2010.

During June 2009, the Company entered into the Second Amendment to the previous credit
facility. The Second Amendment amended certain definitions and certain financial and negative
covenant terms to provide greater flexibility for the Company through the remaining term of the
previous credit facility. Additionally, the Second Amendment increased the interest rates
applicable to borrowings under both the revolver and the term loans. Advances under the revolver
bore interest at LIBOR, with a minimum LIBOR rate, or floor, of 1.5%, plus a margin ranging from
2.25% to 3.0% based on a percentage of usage. The term loan bore interest at LIBOR, also with a
floor of 1.5%, plus a margin of 8.5%, and an additional 2.75% of payment-in-kind interest that was
added to the term loan principal balance on a monthly basis and paid at maturity. At December 31,
2010, $116.5 million was outstanding under the previous revolving credit facility and $80.2 million
was outstanding under the term facility, including $0.2 million accrued payment-in-kind interest.
Due to refinancing of the Companys outstanding debt prior to the issuance of the December 31, 2010
financial statements, the current portion of existing debt at December 31, 2010 was considered
long-term. As previously noted, the Company entered into new credit facilities in March 2011. The
proceeds from the new credit facilities were used to repay the previous credit facility. The
Company expensed the remaining debt issuance costs associated with the previous credit facility
totaling approximately $2.7 million in the first quarter of 2011.

D 

INCOME TAXES

Under guidance contained in Topic 740 of the Accounting Standards
CodificationTM (the Codification), deferred taxes are determined by applying the
provisions of enacted tax laws and rates for the jurisdictions in which the Company operates to the
estimated future tax effects of the differences between the tax basis of assets and liabilities and
their reported amounts in the Companys financial statements. A valuation allowance is established
to reduce deferred tax assets if it is more likely than not that the related tax benefits will not
be realized.

The Company estimates its annual effective income tax rate in recording its quarterly
provision for income taxes in the various jurisdictions in which the Company operates. Statutory
tax rate changes and other significant or unusual items are recognized as discrete items in the
quarter in which they occur. During the three and nine months ended September 30, 2011, the Company
analyzed and made no adjustment to the valuation allowance. During the nine months ended September
30, 2010, the Company reduced the previously recorded valuation allowance by $4.0 million due to its
estimate of taxable income that it projected would be generated in the near future and more likely
than not result in the realization of its deferred tax assets. The reduction in the valuation
allowance was recorded as a discrete item in the second quarter of 2010.

The Company has calculated an estimated effective annual tax rate for the current annual
reporting period, excluding any discrete items, of 41% as of September 30, 2011. The estimated
annual rate differs from the statutory rate primarily due to the
estimate of state income taxes

and non-deductible expenses for the period. Based upon this estimated effective annual tax rate, the
Company has recorded a tax provision of $9.2 million on pre-tax income of $22.1 million for the
nine months ended September 30, 2011. The Company has also recorded additional tax expense of $2.1
million as a discrete item during the three months ended September 30, 2011
related to a revaluation of its deferred tax assets due to the limitations imposed on its net
operating losses under Section 382 of the Internal Revenue Code. For the nine months ended
September 30, 2010, the Company recorded a tax provision of $3.1 million on a pre-tax income of
$5.8 million, based upon its estimated effective annual rate as of that period. In addition, the
Company recorded a $4.0 million tax benefit resulting from a decrease in our valuation allowance as
a discrete item during the nine months ended September 30, 2010.

E 

COMMITMENTS AND CONTINGENCIES

The Company is involved in legal proceedings and litigation in the ordinary course of
business. In the opinion of management, the outcome of such matters will not have a material
adverse effect on the Companys financial position or results of operations.

In May of 2008, the Company drilled the Woolley #1-23 well in Oklahoma. On July 21, 2008 the
Oklahoma Corporation Commission (the OCC) entered a forced pooling order for the Woolley #1-23
well and the Company acquired all of the working interests attributable to those parties who did
not elect to participate in the drilling of the Woolley #1-23 well. Subsequent to the pooling,
certain predecessors in interest that were erroneously omitted from the forced pooling order
disputed the pooling order and sought a determination that they were entitled to share in the
pooled acreage. The OCC determined that the omitted predecessors in interest were not entitled to
share in the pooled acreage; however, the ruling of the OCC was reversed on appeal. As a result,
the Company lost a portion of its working interest in the Woolley #1-23 well and in the McAlester
formation of the 40-acre tract in which the well is located. During the second quarter of 2011,
the Company recorded a charge to other expense of $0.8 million, a reduction in proved oil and gas
properties of $0.2 million and a liability of $0.6 million to record the estimated settlement of
the dispute. During August of 2011, the Company cash settled the $0.6 million liability.

F 

FAIR VALUE MEASUREMENTS

The Company measures the fair value of its derivative instruments according to the fair value
hierarchy as set forth in Topic 820 of the Codification. Topic 820 establishes a fair value
hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The
hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical
assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Level 2 measurements are inputs that are observable for assets or liabilities, either directly or
indirectly, other than quoted prices included within Level 1. The fair value of the Companys net
derivative assets as of September 30, 2011 was $12.6 million and the fair value of the Companys
net derivative assets as of December 31, 2010 was $1.1 million, based on Level 2 criteria. See
Note G.

At September 30, 2011, the carrying value of cash, accounts receivable and accounts payable
reflected in the Companys consolidated financial statements approximates fair value due to their
short-term nature. Additionally, the carrying value of the Companys long-term debt under the
credit facilities approximates fair value because the credit facilities carry a variable interest
rate based on market interest rates. See Note C for discussion of long-term debt.

G 

DERIVATIVE CONTRACTS

The Company periodically utilizes various hedging strategies to achieve a more predictable
cash flow. Various derivative instruments are used to manage the price received for a portion of
the Companys future oil and natural gas production and interest rate swaps are used to manage the
interest rate paid for a portion of the Companys outstanding debt.

During 2011 and 2010, the Company entered into numerous derivative contracts to manage
the impact of oil and natural gas price fluctuations and as required by the terms of its credit
facilities. During the first quarter of 2011, the Company also entered into interest rate swaps to
manage the impact of interest rate fluctuations. The Company did not designate these transactions
as hedges. Accordingly, all gains and losses on the derivative instruments during 2011 and 2010
have been recorded in the statements of operations.

The Companys oil and natural gas derivative positions at September 30, 2011, consisting
of put/call collars, sold put options, which limit the effectiveness of purchased put options at
the low end of the put/call collars to market prices in excess of the strike price of

the put option sold, and bare purchased put options, also called bare floors as they provide a
floor price without a corresponding ceiling, are shown in the following table:

Crude Oil (Bbls)

Natural Gas (Mmbtu)

Collars

Collars

Floors

Ceilings

Put Options Sold

Floors

Ceilings

Bare Floors

Year

Per Day

Price

Per Day

Price

Per Day

Price

Year

Per Day

Price

Per Day

Price

Per Day

Price

Q411

2,150

$80.00

2,150

$105.00

-

-

Q411

-

-

-

-

6,973

$4.17

Q112

2,000

$80.00

2,000

$105.00

1,000

$70.00

Q112

-

-

-

-

6,700

$4.35

Q212

2,000

$80.00

2,000

$105.00

1,000

$70.00

Q212

5,000

$4.00

5,000

$6.00

-

-

Q312

1,900

$92.63

1,900

$105.66

1,238

$70.00

Q312

5,000

$4.00

5,000

$6.00

-

-

Q412

1,750

$92.14

1,750

$104.83

1,138

$70.00

Q412

-

-

-

-

-

-

Q113

1,800

$95.28

1,800

$101.39

1,450

$70.00

Q113

-

-

-

-

-

-

Q213

1,650

$95.00

1,650

$99.93

1,325

$70.00

Q213

-

-

-

-

-

-

Q313

1,600

$95.00

1,600

$99.94

-

-

Q313

-

-

-

-

-

-

Q413

1,550

$95.00

1,550

$99.71

-

-

Q413

-

-

-

-

-

-

Q114

1,600

$95.00

1,600

$100.03

1,600

$70.00

Q114

-

-

-

-

-

-

Q214

1,500

$95.00

1,500

$99.13

1,500

$70.00

Q214

-

-

-

-

-

-

The Companys interest rate derivative positions at September 30, 2011, consisting of
interest rate swaps, are shown in the following table:

Interest Rate Swaps (1)

Notional

Amount

Counterparty

Year

(in millions)

Fixed Rate

Floating Rate (2)

Months Covered

2011

$50

2.51%

3-Month LIBOR

October - December

2012

$50

2.51%

3-Month LIBOR

January - December

2013

$50

2.51%

3-Month LIBOR

January - December

2014

$50

2.51%

3-Month LIBOR

January - March

(1) Settlement is paid to the Company if the counterparty floating rate exceeds
the fixed rate and settlement is paid by the Company if the counterparty floating rate is below the
fixed rate. Settlement is calculated as the difference in the fixed rate and the counterparty
rate.

(2) Subject to a minimum rate of 2%.

The Company estimates the fair value of its derivative instruments based on published
forward commodity price curves as of the date of the estimate, less discounts to recognize present
values. The Company estimates the fair value of its derivatives using a pricing model which also
considers market volatility, counterparty credit risk and additional criteria in determining
discount rates. See Note F.

To determine the fair value of the Companys oil and natural gas derivative instruments,
the discount rate used in the discounted cash flow projections was based on published LIBOR rates,
Eurodollar futures rates and interest swap rates. The counterparty credit risk was determined by
calculating the difference between the derivative counterpartys bond rate and published bond
rates. The Company incorporates its credit risk when the derivative position is a liability by
using its LIBOR spread rate.

Gross fair values of the Companys derivative instruments, prior to netting of assets and
liabilities subject to a master netting arrangement, as of September 30, 2011 and December 31, 2010
and the consolidated statements of operations for the three and nine months ended September 30,
2011 and 2010 are as follows (in thousands):

During April 2011, pursuant to the Companys new credit facilities entered into in March 2011,
the Company was required to reduce the volume of its existing crude oil and natural gas derivatives
so it would not exceed the maximum allowable volumes for future production periods and to novate
derivative contracts to counterparties that are lenders within the new credit facilities. During
the second quarter of 2011, the Company recognized $0.9 million in realized losses on the unwinding
of the excess crude oil and natural gas derivatives and the $0.5 million in fees paid to complete
the novation, both of which are included in realized gains and losses on derivatives in the income
statement.

H 

SHARE-BASED COMPENSATION

The Company accounts for share-based payment accruals under authoritative guidance on stock
compensation, as set forth in Topic 718 of the Codification. The guidance requires all share-based
payments to employees, including grants of employee stock options, to be recognized in the
financial statements based on their fair values.

On May 8, 2006, the Companys stockholders approved its 2006 Long-Term Incentive Plan (the
Plan). The Company reserved a maximum of 2,400,000 shares of its common stock for issuances under
the Plan. The Plan includes a provision that, at the request of a grantee, the Company may
repurchase shares to satisfy the grantees federal and state income tax withholding requirements.
All repurchased shares will be held by the Company as treasury stock. On May 8, 2008, the Plan was
amended to increase the maximum authorized number of shares

to be issued under the Plan from 2,400,000 to 6,000,000. On May 3,
2010, the Plan was amended to increase the maximum authorized number of shares to be issued under
the Plan from 6,000,000 to 7,400,000. As of September 30, 2011, 1,216,801 shares of common stock
remained reserved for issuance under the Plan.

As of September 30, 2011, the Company had $3.8 million of unrecognized compensation related to
common stock awards granted under the Plan. That cost is expected to be recognized over a
weighted-average period of two years. The related compensation recognized during the three and nine
months ended September 30, 2011 was $0.9 million and $2.5 million, respectively, and during the
three and nine months ended September 30, 2010 was $0.8 million and $2.3 million, respectively.
During the three and nine months ended September 30, 2011, $0.7 million and $2.1 million,
respectively, of recognized compensation was recorded as compensation expense and $0.2 million and
$0.4 million, respectively, was recorded as capitalized internal costs. During the three and nine
months ended September 30, 2010, all recognized compensation was recorded to compensation expense.

In May 2011, the Company granted 1,530,500 stock appreciation rights (SARs) under the Plan
at an exercise price of $1.73 per share, which was the weighted average closing price of the
Companys common stock on the date of grant. Compensation expense related to the SARs is based on
fair value re-measured at each reporting period and recognized over the vesting period (generally
four years). As of September 30, 2011, the fair value calculation resulted in $0.1 million expense
recognized during the three and nine months ended September 30, 2011. The SARs expire ten years
from date of grant and upon exercise. The Company will settle the SARs in cash, net of the
applicable taxes.

The Company uses the Black-Scholes option pricing model to compute the fair value of the SARs.
The following assumptions were used in calculating fair value:



The risk-free interest rate is based on the zero coupon
United States Treasury yield for the expected life of the
grant.



The dividend yield on the Companys common stock is assumed
to be zero since the Company does not pay dividends and has
no current plans to do so in the future.



The volatility of the Companys common stock is based on
volatility of the market price of the Companys common stock
over a period of time equal to the expected term and ending
on the grant date.

I 

SUBSEQUENT EVENTS

On October 7, 2011, the Company announced the retirement of certain Company officers and a
Company-wide reorganization of its operating and administrative functions (the Reorganization).
The Reorganization was approved by the Companys Board of Directors on October 4, 2011. As part of
the Reorganization, the retirement and termination of employment of the affected officers and
employees started during October of 2011 and will be completed in full by June 2012.

As part of the Reorganization, the Board of Directors authorized the Company to offer certain
severance benefits to the affected officers and employees on terms specified by the Board
(collectively, the Severance Program). The estimated total expense of the Severance Program is
approximately $2.6 million, which includes approximately $1.8 million in one-time severance
payments and approximately $0.8 million of stock compensation expense related to the acceleration
of restricted stock awards.

We are an independent oil and natural gas company engaged in the development,
acquisition, exploitation, exploration and production of oil and natural gas properties, primarily
in Texas, Oklahoma and Louisiana. Our producing properties are located in highly prolific basins
with long histories of oil and natural gas operations.

Principal Properties

Our principal oil and natural gas properties are located in the following fields:

We also own and operate other oil and natural gas properties in Texas, Oklahoma,
Louisiana, New Mexico, Mississippi and West Virginia.

In August 2011, we entered into an agreement in principle to sell a majority interest in our
Electra/Burkburnett field, located in Wichita and Wilbarger Counties, Texas, to Argent Energy
Trust, a recently formed Canadian energy trust. The sale is contingent upon the successful
completion of the initial public offering, or IPO, of trust units, the negotiation and execution of
a definitive purchase and sale agreement and execution of an agreement for the further development
of the property with us continuing to serve as operator following the closing. Due to the recent
market conditions, the possible sale of our interest in our Electra/Burkburnett properties has been
put on hold pending such improvement in market conditions as will permit completion of the Argent
IPO. The offering of trust units of Argent Energy Trust will be made within the United States only
by Argent to qualified institutional buyers in reliance on Rule 144A under the Securities Act of
1933, as amended (the Securities Act). The securities to be offered by Argent have not been
registered under the Securities Act or any state securities laws, and unless so registered, may not
be offered or sold in the United States except pursuant to an exemption from, or in a transition
not subject to, the registration requirements of the Securities Act and applicable state securities
law.

The following table presents certain information with respect to our oil and natural gas
production, and prices and costs attributable to all oil and natural gas properties owned by us,
for the three and nine months ended September 30, 2011. Average realized prices reflect the actual
realized prices received by us, before and after giving effect to the results of our derivative
contract settlements. Our derivative activities are financial, and our production of oil, natural
gas liquids, or NGLs, and natural gas, and the average realized prices we receive from our
production, are not affected by our derivative arrangements.

Three Months Ended

Nine Months Ended

September 30, 2011

September 30, 2011

Production volumes:

Oil (MBbls)

213

661

NGL (MBbls)

45

136

Natural gas (MMcf)

615

1,985

Total (MBoe)

361

1,128

Average sale prices received:

Oil (per Bbl)

$

88.99

$

94.02

NGL (per Bbl)

$

58.76

$

55.75

Natural gas (per Mcf)

$

4.14

$

4.16

Total per Boe

$

66.89

$

69.13

Cash effect of derivative contracts:

Oil (per Bbl)

$

(0.34

)

$

(4.61

)

NGL (per Bbl)

$

-

$

-

Natural gas (per Mcf)

$

0.24

$

0.94

Total per Boe

$

0.21

$

(1.05

)

Average prices computed after cash effect of settlement
of derivative contracts:

The following table presents information regarding our net costs incurred in our
acquisitions of proved and unproved properties, and our development and exploration activities
during the three and nine months ended September 30, 2011 (in thousands):

Three months ended

Nine months ended

September 30, 2011

September 30, 2011

Development and exploratory costs

$

5,830

$

18,883

Proved property acquisition costs

270

717

Total costs incurred

$

6,100

$

19,600

During the quarter ended September 30, 2011, we participated in the drilling of 14 gross
(11.5 net) development wells and two gross (2.0 net) exploration wells. Eight gross (8.0 net)
development wells were capable of production. Six gross (3.5 net) development wells were either
drilling or waiting on completion as of September 30, 2011. Two gross (2.0 net) exploration wells
were waiting on completion at September 30, 2011.

The following tables summarize our oil and natural gas production volumes, average sale
prices (without regard to derivative contract settlements) and period-to-period comparisons for the
periods indicated:

Texas

Oklahoma

Louisiana

Other

Total

Three Months Ended September 30, 2011

Aggregate net Production

Oil (MBbls)

116

76

14

7

213

NGLs (MBbls)

37

5

-

3

45

Natural Gas (MMcf)

363

99

119

34

615

MBoe

214

98

34

15

361

Texas

Oklahoma

Louisiana

Other

Total

Three Months Ended September 30, 2010

Aggregate net Production

Oil (MBbls)

134

81

23

9

247

NGLs (MBbls)

85

2

-

4

91

Natural Gas (MMcf)

802

208

167

38

1,215

MBoe

353

118

51

19

541

Change in MBoe

(139

)

(20

)

(17

)

(4

)

(180

)

% change in MBoe

-39.4

%

-16.9

%

-33.3

%

-21.1

%

-33.3

%

Three months ended

September 30,

2011

2010

Increase

Average sale prices:

Oil (per Bbl)

$

88.99

$

74.05

20.2

%

NGL (per Bbl)

$

58.76

$

35.71

64.5

%

Natural gas (per Mcf)

$

4.14

$

4.05

2.2

%

Per Boe

$

66.89

$

48.91

36.8

%

In December 2010, we sold assets located in Texas and Oklahoma for net proceeds including
post-closing adjustments of $48.8 million. The following table provides pro forma results for 2010
excluding those sold properties to assist our description of results of operations:

Oil and natural gas sales decreased $2.3 million, or 9%, to $24.1 million for the three
months ended September 30, 2011, as compared to $26.5 million for the three months ended
September 30, 2010. Excluding assets sold, oil and natural gas sales increased by $0.2 million for
the three months ended September 30, 2011, as compared to the same period in 2010. This increase
was driven by higher commodity prices during the 2011 period, offset by decreased production.

Production volumes decreased 33% for the three months ended September 30, 2011 as
compared to the same period last year. Excluding the activities related to the asset divestitures,
our production volume decreased 20% for the three months ended September 30, 2011 as compared to
the same period last year primarily due to a shut-in of one well as a result of a major workover in
Louisiana and normal production declines. Production from our Texas fields decreased 66 MBoe in the
third quarter, excluding asset sales, due to normal production declines from new wells drilled in
2010. Drilling activity included eight gross (8.0 net) development wells which were capable of
production and five gross (3.5 net) development wells that were either drilling or waiting on
completion in our Texas fields. Production from our Oklahoma fields decreased 5 MBoe in the third
quarter, excluding asset sales, primarily due to natural production declines. Drilling activity in
Oklahoma included two gross (2.0 net) exploratory wells. Production from our Louisiana fields
decreased 17 MBoe in the third quarter 2011 due to a shut-in of one well and normal production
declines. We did not drill any new wells in our Louisiana fields during the third quarter of 2011.

The average realized sales prices on a Boe basis increased substantially for the three
months ended September 30, 2011, as compared to the same period in 2010. The average realized sales
price for oil was $88.99 per barrel for the three months ended September 30, 2011, an increase of
20%, compared to $74.05 per barrel for the same period in 2010. The average realized sales price
for NGLs was $58.76 per barrel for the three months ended September 30, 2011, an increase of 65%,
compared to $35.71 per barrel for the same period in 2010. The average realized sales price for
natural gas was $4.14 per Mcf for the three months ended September 30, 2011, an increase of 2%,
compared to $4.05 per Mcf for the same period in 2010. The positive impact from the 37% increase in
total average price per Boe in the third quarter of 2011 did not fully offset the impact of asset
sales and normal production declines, causing oil and natural gas sales for the third quarter to
decline to $24.1 million compared to $26.5 million in the prior year period.

We recorded income before income taxes of $24.9 million for the quarter ended
September 30, 2011, as compared to zero income before income taxes for the quarter ended
September 30, 2010. Excluding unrealized gains on derivatives of $22.7 million, our adjusted income
before income taxes for the quarter ended September 30, 2011 was $2.2 million. Excluding unrealized
gains on derivatives of $1.8 million, our adjusted loss before income taxes for the quarter ended
September 30, 2010 was $1.8 million.

Realized and Unrealized Gain (Loss) from Commodities Derivatives. For the quarter ended
September 30, 2011, our gain from derivatives was $22.8 million, compared to $0.6 million for the
quarter ended September 30, 2010. Our gains and losses during these periods were the net result of
recording actual contract settlements, the premiums for our derivative contracts, and unrealized
gains and losses attributable to mark-to-market values of our derivative contracts at the end of
the periods.

Oil and Natural Gas Production Taxes. Excluding asset sales, our oil and natural gas
production taxes remained flat at $1.4 million for the quarter ended September 30, 2011 as compared
to the year ago quarter. Most production taxes are based on realized prices at the wellhead, while
Louisiana production taxes are based on volumes for natural gas and values for oil. As revenues or
volumes from oil and natural gas sales increase or decrease, production taxes on these sales also
increase or decrease directly. As a percentage of oil and natural gas sales, our oil and natural
gas production taxes were approximately 6% for each of the quarters ended September 30, 2011 and
2010.

Oil and Natural Gas Production Expense. Our oil and natural gas production expenses were
$7.5 million for the quarter ended September 30, 2011, a decrease of $0.6 million, or 7%, from the
$8.1 million, excluding asset sales, for the quarter ended September 30, 2010. The decrease is
primarily due to decreased production volumes, decline in nonrecurring lease operating expenses as
well as lower property taxes and utility costs during the 2011 period. Our oil and natural gas
production expense was $20.77 per Boe for the quarter ended September 30, 2011 compared to $15.84
per Boe for the quarter ended September 30, 2010, an increase of 31%. The increase per Boe is
primarily due to the asset sales, as the sold assets in 2010 were predominantly shale gas producing
assets which had relatively lower lease operating expenses per Boe. As a percentage of oil and
natural gas sales, oil and natural gas production expense was 31% for the quarter ended
September 30, 2011, as compared to 32% for the quarter ended September 30, 2010. This decrease is
due to the decline in production expenses as well as higher commodity prices in the 2011 period.

Amortization and Depreciation Expense. Our amortization and depreciation expense
decreased $1.6 million, or 24%, for the quarter ended September 30, 2011, as compared to the
quarter ended September 30, 2010. The decline was a result of a decrease in production during the
2011 period, offset by a higher depletion rate per Boe. On an equivalent basis, our amortization of
the full-cost pool of $4.9 million was $13.69 per Boe for the quarter ended September 30, 2011, as
compared to $6.5 million, or $12.06 per Boe, for the quarter ended September 30, 2010.

Accretion Expense. Topic 410 of the Codification, Accounting for Asset Retirement
Obligations, includes, among other things, the reporting of the fair value of asset retirement
obligations. Accretion expense is a function of changes in fair value from period-to-period. We
recorded accretion expense of $0.4 million for the quarter ended September 30, 2011, compared to
$0.5 million for the quarter ended September 30, 2010. The decrease was related to the sold assets
offset by changes in our estimates.

Share-Based Compensation. From time to time, our Board of Directors grants restricted
stock awards and/or stock appreciation rights (SARs) under our 2006 Long-Term Incentive Plan.
Each of the restricted stock grants vests in equal increments over the vesting period provided for
the particular award. All currently unvested restricted stock awards provide for vesting periods
from one to five years. The share-based compensation expense attributable to restricted stock
grants is calculated using the closing price per share on each of the grant dates and will be
recognized over their respective vesting periods. Share-based compensation expense attributable to
SARs is based on the fair value re-measured at each reporting period and recognized over the
four-year vesting period. The fair value calculation resulted in $0.1 million of compensation
expense recognized for the three months ended September 30, 2011. For the quarter ended
September 30, 2011, we recognized a total of $0.9 million share-based compensation related to
restricted stock awards as compared to $0.8 million for the comparable quarter for the previous
year. The increase was primarily due to a higher number of shares outstanding in the 2011 period.
During the three months ended September 30, 2011, $0.7 million of recognized compensation related
to restricted stock awards was recorded as compensation expense and $0.2 million was recorded as
capitalized internal costs.

General and Administrative Expense. For the quarter ended September 30, 2011, our
general and administrative expense was $3.1 million, compared to $2.9 million for the quarter ended
September 30, 2010, an increase of $0.2 million, or 6%. The increase was primarily due to higher
employee related costs in the 2011 period.

Interest Expense. We recorded interest expense of $3.6 million for the quarter ended
September 30, 2011, as compared to $5.8 million for the third quarter of the previous year. The
decrease in interest expense was due to lower interest rates and lower average outstanding
borrowings throughout the 2011 period. Our blended interest rate as of September 30, 2011 and 2010
was 6.2% and 8.2%, respectively.

Loss on Interest Rate Derivatives. We incurred $0.2 million net realized and unrealized
loss attributable to mark-to-market value of interest rate swaps in the third quarter of 2011. We
had no interest rate derivatives in effect in the year ago quarter.

Other Income (Expense). For the three months ended September 30, 2011, our other income
was $0.2 million, compared to other expense of $0.3 million for the three months ended
September 30, 2010. The decrease in other expense is primarily due to a charge relating to pipe
inventory write-off in the 2010 period.

Income Taxes. For the three months ended September 30, 2011, we recorded income tax
expense of $11.0 million on pre-tax income of
$24.9 million. We have also recorded additional tax expense of
$2.1 million as a discrete item during the three months ended
September 30, 2011
related to the revaluation of our deferred tax assets due to the limitations imposed on our net
operating losses under Section 382 of the Internal Revenue Code. For the three months ended
September 30, 2010, we recorded income tax benefit of $1.6 million.

The following tables summarize our oil and natural gas production volumes, average sale
prices (without regard to derivative contract settlements) and period-to-period comparisons for the
periods indicated:

In December 2010, we sold assets located in Texas and Oklahoma for net proceeds including
post-closing adjustments of $48.8 million. The following table provides pro forma results for the
nine months ended September 30, 2010 excluding those sold properties to assist our description of
results of operations:

Nine months ended September 30, 2010

Sold

Actual

Assets

Pro Forma

Oil and natural gas sales (in thousands):

Oil

$

56,898

$

957

$

55,941

Natural gas

16,170

4,001

12,169

NGLs

10,461

3,875

6,586

Total oil and natural gas sales

$

83,529

$

8,833

$

74,696

Production expenses (in thousands):

Oil and natural gas production taxes

$

4,565

$

380

$

4,185

Oil and natural gas production expenses

$

25,153

$

1,418

$

23,735

Production volumes (MBoe):

Texas

1,094

244

850

Oklahoma

358

49

309

Other

204

-

204

Total production

1,656

293

1,363

Oil and natural gas sales decreased $5.5 million, or 7% to $78.0 million for the nine
months ended September 30, 2011, as compared to $83.5 million for the same period in 2010.
Excluding asset sales, oil and natural gas sales increased $3.3 million for the nine months ended
September 30, 2011 as compared to the same period in 2010. This increase was driven primarily by
higher commodity prices during the 2011 period, partially offset by decreased production.

Production volumes decreased 32% as compared to the same period last year. Excluding the
activities related to the asset divestitures, our production volume decreased 17% as compared to
the same period last year primarily due to a shut-in of one well as a result of a major workover in
Louisiana and normal production declines. Production from our Texas fields decreased 162 MBoe for
the first nine months of 2011, excluding asset sales, due to a decline in well performance in our
South Texas gas properties and from normal production declines. Drilling activity included 33 gross
(30.8 net) development wells in our Texas fields. Of the 33 gross development wells in our Texas
fields, 28 gross (27.3 net) wells were capable of production and five gross (3.5 net) wells were
either drilling or waiting on completion. Production from our Oklahoma fields decreased 27 MBoe for
the first nine months of 2011, excluding asset sales, primarily due to natural production declines.
Drilling activity in Oklahoma included one gross (0.2 net) development well and nine gross (9.0
net) exploratory wells. Production from our Louisiana fields decreased 39 MBoe for the first nine
months of 2011 due to a shut-in of one well and normal production declines. We did not drill any
new wells in our Louisiana fields during the nine months ended September 30, 2011.

The average realized sales prices increased substantially for the nine months ended
September 30, 2011, as compared to the same period in 2010. The average realized sales price for
oil was $94.02 per barrel for the nine months ended September 30, 2011, an increase of 25%,
compared to $75.16 per barrel for the same period in 2010. The average realized sales price for
NGLs was $55.75 for the nine months ended September 30, 2011, an increase of 49%, compared to
$37.36 per barrel for the same period in 2010. The average realized sales price for natural gas was
$4.16 per Mcf for the nine months ended September 30, 2011, a decrease of 4%, compared to $4.35 per
Mcf for the same period in 2010. The positive impact from the 37% increase in total average price
per Boe in the first nine months of 2011 did not fully offset the impact of asset sales and normal
production declines, causing oil and natural gas sales for the first nine months of 2011 to decline
to $78.0 million compared to $83.5 million in the same period in 2010.

We recorded income before income taxes of $22.1 million for the nine months ended
September 30, 2011, an increase of $16.3 million, as compared to $5.8 million for the nine months
ended September 30, 2010. Excluding unrealized gains on derivatives of $18.5 million and debt
extinguishment and loan amortization costs of $2.7 million, our adjusted income before income taxes
for the nine months ended September 30, 2011 was $6.3 million. Excluding unrealized gains on
derivatives of $6.1 million, our adjusted loss before income taxes for the nine months ended
September 30, 2010 was $0.3 million.

Realized and Unrealized Gain (Loss) from Commodities Derivatives. For the nine months
ended September 30, 2011, our gain from derivatives was $17.3 million, compared to $3.3 million for
the nine months ended September 30, 2010. Our gains and losses during these periods were the net
result of recording actual contract settlements, the premiums for our derivative contracts, and
unrealized gains

and losses attributable to mark-to-market values of our derivative contracts at
the end of the periods. During the nine months ended September 30, 2011, we recognized $0.9 million
in realized losses on the unwinding of the excess crude oil and natural gas derivatives and
$0.5 million in fees paid to complete the novation of derivative contracts to counterparties that
are lenders within our new credit facilities, both of which are included with other settlements of
$0.2 million in realized gains and losses on derivatives and required under the terms of the new
credit facilities.

Nine months ended September 30,

2011

2010

(in thousands)

Contract settlements and premium costs:

Oil

$

(3,044

)

$

(3,088

)

Natural gas

1,858

270

Realized losses

(1,186

)

(2,818

)

Mark-to-market gains (losses):

Oil

19,606

3,577

Natural gas

(1,087

)

2,559

Unrealized gains

18,519

6,136

Realized and unrealized gains

$

17,333

$

3,318

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes were
$4.3 million for the nine months ended September 30, 2011, compared to $4.2 million, excluding
asset sales, for the comparable nine months of the previous year. The increase is due principally
to higher commodity prices in the 2011 period. Production taxes vary by state. Most production
taxes are based on realized prices at the wellhead, while Louisiana production tax is based on
volumes for natural gas and value for oil. As revenues or volumes from oil and natural gas sales
increase or decrease, production taxes on these sales also increase or decrease directly. As a
percentage of oil and natural gas sales, oil and natural gas production taxes were 5% for the nine
months ended September 30, 2011 and 2010.

Oil and Natural Gas Production Expense. Our oil and natural gas production expenses were
$24.0 million for the nine months ended September 30, 2011, an increase of $0.3 million, or 1%,
from the $23.7 million, excluding asset sales, for the nine months ended September 30, 2010. For
the nine months ended September 30, 2011, our oil and natural gas production expense was $21.32 per
Boe compared to $15.19 per Boe for the nine months ended September 30, 2010, an increase of 40%.
The increase per Boe is primarily due to the asset sales, as the sold assets in 2010 were
predominantly shale gas producing assets which had relatively lower lease operating expenses per
Boe. As a percentage of oil and natural gas sales, oil and natural gas production expense was 31%
for the nine months ended September 30, 2011, as compared to 30% for the nine months ended
September 30, 2010. This increase results from the decrease in oil and natural gas sales due to a
decline in production in the 2011 period.

Amortization and Depreciation Expense. Our amortization and depreciation expense
decreased $4.7 million, or 23%, for the nine months ended September 30, 2011, compared to the nine
months ended September 30, 2010. The decrease was a result of a decrease in production during the
2011 period, offset by a higher depletion rate per Boe. On an equivalent basis, our amortization of
the full-cost pool of $14.9 million was $13.22 per Boe for the nine months ended September 30,
2011, an increase per Boe of 12% compared to $19.6 million, or $11.83 per Boe for the nine months
ended September 30, 2010.

Accretion Expense. Topic 410 of the Codification, Accounting for Asset Retirement
Obligations, includes, among other things, the reporting of the fair value of asset retirement
obligations. Accretion expense is a function of changes in fair value from period-to-period. We
recorded $1.2 million for the nine months ended September 30, 2011, compared to $1.3 million for
the first nine months in 2010. The decrease is primarily due to the sold assets offset by changes
in our estimates.

Share-Based Compensation. From time to time, our Board of Directors grants restricted
stock awards and/or SARs under our 2006 Long-Term Incentive Plan. Each of the restricted stock
grants vests in equal increments over the vesting period provided for the particular award. All
currently unvested restricted stock awards provide for vesting periods from one to five years. The
share-based compensation on the restricted stock grants was calculated using the closing price per
share on each of the grant dates, and the total share-based compensation on all restricted stock
grants will be recognized over their respective vesting periods. Share-based compensation expense
attributable to SARs is based on the fair value re-measured at each reporting period and recognized
over the four-year vesting period. The fair value calculation resulted in $0.1 million of
compensation expense recognized for the nine months ended September 30, 2011. For the nine months
ended September 30, 2011, we recognized a total of $2.5 million share-based compensation related to
restricted stock awards compared to $2.3 million for the nine months ended September 30, 2010. The
increase was primarily due to a higher number of shares outstanding in the 2011 period. During the
nine months ended September 30, 2011, $2.1 million of recognized compensation related to restricted
stock awards was recorded as compensation expense and $0.4 million was recorded as capitalized
internal costs.

General and Administrative Expense. For the nine months ended September 30, 2011, our
general and administrative expense was $10.9 million, compared to $10.7 million for the nine months
ended September 30, 2010, an increase of $0.2 million, or 2%.The increase was a result of higher
employee related costs in the 2011 period.

Interest Expense. We recorded interest expense of $13.8 million for the nine months
ended September 30, 2011, as compared to $17.1 million for the first nine months of the previous
year. Of that $13.8 million, we incurred $2.7 million in debt extinguishment costs and $0.4 million
in payment-in- kind interest related to our old credit facility in the first nine months of 2011.
The decrease in interest expense was due to lower interest rates and lower average outstanding
borrowings throughout the 2011 period. Our blended interest rate as of September 30, 2011 and 2010
was 6.2% and 8.2%, respectively.

Loss on Interest Rate Derivatives. We incurred $0.7 million net realized and unrealized
loss attributable to interest rate swaps for the nine months ended September 30, 2011. Our realized
and unrealized loss was the net result of recording actual contract settlements and unrealized
losses attributable to the mark-to-market values of our interest rate swap contract at the end of
the period. We had no interest rate derivatives in effect in the nine months ended September 30,
2010.

Other Income (Expense). For the nine months ended September 30, 2011, our other expense
was $0.6 million, compared to other income of $0.3 million for the nine months ended September 30,
2010. The increase in other expense is primarily due to a litigation settlement recorded in 2011.
For the nine months ended September 30, 2010, we reduced a contingency accrual by $0.6 million
related to settlement of pending litigation offset by a charge relating to pipe inventory
write-off.

Income Taxes. For the nine months ended September 30, 2011, we recorded income tax
expense of $9.2 million on pre-tax income of $22.1 million. We have also recorded additional tax
expense of $2.1 million as a discrete item during the nine months ended September 30, 2011 related
to the revaluation of our deferred tax assets due to the limitations imposed on our net operating
losses under Section 382 of the Internal Revenue Code. For the nine months ended September 30,
2010, we recorded income tax expense of $3.1 million on pre-tax income of $5.8 million. In
addition, we recorded a $4.0 million tax benefit resulting from a decrease in our valuation
allowance as a discrete item during the nine months ended September 30, 2010.

Liquidity and Capital Resources

As of September 30, 2011, we had cash and cash equivalents of less than $0.1 million, and
$25.0 million of nominal availability under our revolving credit facility. In March 2011, we
entered into new credit facilities including a $250.0 million first lien revolving credit facility
with an initial $150.0 million borrowing base and a $75.0 million second lien term loan facility.
Under our new credit facilities, through September 30, 2011, additional borrowings will not be
limited by the leverage ratio covenant in our revolving loan agreement provided our Modified EBITDA
for the preceding four fiscal quarters exceeds $47.4 million. Our Modified EBITDA for the four
fiscal quarters ending September 30, 2011 was $47.8 million. Management believes that borrowings
currently available to us under our credit facilities and anticipated cash flows from operations
will be sufficient to satisfy our currently expected capital expenditures, working capital, and
debt service obligations for the foreseeable future. At September 30, 2011, we had $200.4 million
of indebtedness outstanding, including $125.0 million under our revolving credit facility,
$75.0 million under our term loan credit facility and $0.4 million in other indebtedness. As of
September 30, 2011, we had an accumulated deficit of $204.1 million and a working capital deficit
of $6.0 million.

Credit Facilities . In March 2011, we entered into new credit facilities. The new
facilities, which replaced our previous facility, include a $250.0 million first lien revolving
credit facility and a $75.0 million second lien term loan facility. SunTrust Bank is the
administrative agent for the revolving facility, and Guggenheim Corporate Funding, LLC is the
administrative agent for the term loan facility. The current borrowing base under the revolving
credit facility is $150.0 million. The borrowing base is reviewed and redetermined effective
March 31 and September 30 of each year, and between scheduled redeterminations upon request. On
September 30, 2011, the borrowing base was reaffirmed at $150.0 million based on the value of our
proved reserves at June 30, 2011. Funds advanced under the revolving credit facility may be paid
down and re-borrowed during the five-year term of the revolver, and bear interest at LIBOR plus a
margin ranging from 2.5% to 3.25% based on a percentage of usage. The term loan credit facility
provides for payments of interest only during its 5.5-year term, with the interest rate being LIBOR
plus 9.0% with a 2.0% LIBOR floor, or if in any period we elect to pay a portion of the interest
under our term loan in kind, then the interest rate will be LIBOR plus 10.0% with a 2.0% LIBOR
floor, and with 7.0% of the interest amount paid in cash and the remaining 3.0% paid in kind by
being added to principal.

Advances under our credit facilities are secured by liens on substantially all of our
properties and assets. The credit facilities contain representations, warranties and covenants
customary in transactions of this nature, including restrictions on the payment of dividends on our
capital stock and financial covenants relating to current ratio, minimum interest coverage ratio,
maximum leverage ratio and a required ratio of asset value to total indebtedness. We are required
to maintain commodity hedges on a rolling basis for the first 12 months of not less than 60%, but
not more than 85%, and for the next 18 months of not less than 50% but not more than 85%, of our
projected quarterly production volumes, until the leverage ratio is less than or equal to 1.5 to
1.0. At September 30, 2011, our commodity hedging represented approximately 65% of our projected
production volumes through June 30, 2014. During June 2011, we entered into the First Amendment to
the revolving credit facility. The First Amendment amended certain definitions affecting covenant
calculations and modified the terms of our natural gas derivative counterparty requirements.

Our previous credit facility entered into November 2007 included a $500.0 million credit
facility with Guggenheim Corporate Funding, LLC, for itself and on behalf of other institutional
lenders. This facility included a $250.0 million revolving
credit facility, a $200.0 million

term
loan facility, and an additional $50.0 million available under the term loan as requested by us and
approved by the lenders. The entire amount of the $200.0 million term loan was advanced at closing.
The borrowing base under our previous revolving credit facility was $145.0 million at December 31,
2010. Funds advanced under the revolving credit facility initially bore interest at LIBOR plus a
margin ranging from 1.25% to 2.0% based on a percentage of usage. The term loan portion of our
credit facility initially provided for payments of interest only during its five-year term, with
the initial interest rate being LIBOR plus 7.5%.

On June 26, 2009, we renegotiated certain terms of our previous credit facility to
provide us greater flexibility in complying with certain of the financial covenants under the loan
agreement. In exchange for the added flexibility afforded by these changes to the credit facility,
we agreed to increase the base cash interest rate on both the revolving credit facility and the
term loan credit facility by 1% per annum, establish a LIBOR floor of 1.5% and pay an additional
2.75% per annum of non-cash, payment-in-kind, or PIK, interest on the term portion of the facility.
Accrued PIK interest was added to the principal balance of the term loan on a monthly basis and was
paid in connection with the closing of the new credit facilities in March 2011.

In December 2010, we used $33.8 million in proceeds from asset sales to pay down the term
facility and $24.0 million in proceeds from asset sales to pay down the revolving credit facility.
PIK interest of $3.0 million was added to the term facility in 2010, and $0.4 million was added to
the term facility in the first quarter of 2011, bringing the balance of the term facility to $80.6
million at the date of the closing of the new credit facilities on March 14, 2011.

Our ability to comply with the financial covenants in our new credit facilities may be
affected by events beyond our control and, as a result, in future periods we may be unable to meet
these ratios and financial condition tests. These financial ratio restrictions and financial
condition tests could limit our ability to obtain future financings, make needed capital
expenditures, withstand a future downturn in our business or the economy in general or otherwise
conduct necessary corporate activities. A breach of any of these covenants or our inability to
comply with the required financial ratios or financial condition tests could result in a default
under our credit facilities. A default, if not cured or waived, could result in acceleration of all
indebtedness outstanding under our credit facilities. The accelerated debt would become immediately
due and payable. If that should occur, we may be unable to pay all such debt or to borrow
sufficient funds to refinance it. Even if new financing were then available, it may not be on terms
that are acceptable to us. At September 30, 2011, we were in compliance with all of the financial
covenants under our credit facilities.

At-The-Market Program . On March 17, 2011, we filed a prospectus supplement under which
we may, from time to time, sell up to $25.0 million of our common stock through an at-the-market
equity distribution program (the At-The-Market Program). Shares would be offered pursuant to the
prospectus supplement dated March 17, 2011 to our base prospectus dated February 24, 2010, which
was filed as part of our effective shelf registration statement. As of September 30, 2011, we had
made no sales of common stock through the At-The-Market Program.

Cash Flow From Operating Activities . Our cash flow from operating activities is
comprised of three main items: net income, adjustments to reconcile net income to cash provided
(used) before changes in working capital, and changes in working capital. For the nine months ended
September 30, 2011, our net income was $10.8 million, as compared to $6.7 million for the nine
months ended September 30, 2010. Adjustments (primarily non-cash items such as depreciation and
amortization, unrealized (gains) losses and deferred income taxes) were $17.5 million for the nine
months ended September 30, 2011, compared to $22.5 million for the first nine months of 2010, a
decrease of $5.0 million. The change in unrealized (gains) losses and depreciation and amortization
partially offset by the change in deferred income taxes caused most of this decrease. Working
capital changes for the nine months ended September 30, 2011 were a negative $4.5 million compared
to working capital changes of $0.1 million for the nine months ended September 30, 2010. For the
nine months ended September 30, 2011 and 2010, in total, net cash provided by operating activities
was $23.8 million and $29.3 million, respectively.

Cash Flow From Investing Activities . For the nine months ended September 30, 2011, net
cash used in our investing activities was $19.6 million, consisting of $20.1 million in payments
for oil and gas properties and other equipment offset by $0.5 million in proceeds from sales of
property and equipment. For the nine months ended September 30, 2010, net cash used in our
investing activities was $27.7 million.

Cash Flow From Financing Activities . For the nine months ended September 30, 2011, net
cash used in our financing activities was $4.2 million, compared to $1.7 million for the nine
months ended September 30, 2010. During the first nine months of 2011, we received proceeds of
$238.2 million from borrowings on long-term debt. We also reduced our long-term debt by
$235.2 million, paid $7.0 million for deferred loan costs, and incurred $0.1 million in common
stock repurchased from participants under our 2006 Long-Term Incentive Plan to net settle
withholding tax liability. During the first nine months of 2010, we received proceeds of $36.3
million from borrowings on long-term debt, which was offset by $37.6 million of payments made to
reduce our long term debt and $0.3 million in common stock repurchased from participants under our
2006 Long-Term Incentive Plan to net settle withholding tax liability.

Capital Commitments

We have revised our budget to $27.5 million for non-acquisition capital expenditures in
2011 related to:

In our 2011 non-acquisition capital budget for developmental drilling and recompletions,
we have allocated $7.9 million for continued development of our Electra/Burkburnett area, $2.8
million for recompletions in our Louisiana properties, $0.8 million for recompletions in our South
Texas properties and $2.0 million for reworking and production enhancement operations in other
fields, including our Fitts and Allen fields in Oklahoma.

During the nine months ended September 30, 2011, we had capital expenditures of
$19.6 million relating to our oil and natural gas operations, of which $9.2 million was allocated
to developmental drilling and recompletions, $5.4 million was allocated to exploration, including
leasehold acquisition, seismic and exploratory drilling, and $5.0 million was allocated to
geological, geophysical, contingencies and capitalized general and administrative costs.

The amount and timing of our capital expenditures for calendar year 2011 may vary depending on
a number of factors, including prevailing market prices for oil and natural gas, the favorable or
unfavorable results of operations actually conducted, projects proposed by third party operators on
jointly owned acreage, development by third party operators on adjoining properties, rig and
service company availability, and other influences that we cannot predict.

Although we cannot provide any assurance, assuming successful implementation of our
strategy, including the future development of our proved reserves and realization of our cash flows
as anticipated, we believe that cash flows from operations and the availability under our revolving
credit facility will be sufficient to satisfy our budgeted non-acquisition capital expenditures,
working capital and debt service obligations for the foreseeable future. The actual amount and
timing of our future capital requirements may differ materially from our estimates as a result of,
among other things, changes in product pricing and regulatory, technological and competitive
developments. Sources of additional financing available to us may include commercial bank
borrowings, vendor financing, asset sales and the sale of equity or debt securities. We cannot
provide any assurance that any such financing will be available on acceptable terms or at all.

The credit markets are undergoing significant volatility. Many financial institutions
have liquidity concerns, prompting government intervention to mitigate pressure on the credit
markets. Our exposure to the current credit market crisis includes our revolving credit facility,
counterparty risks related to our trade credit and risks related to our cash investments.

Our revolving credit facility matures in March 2016. Our term loan facility matures in
September 2016. Should the current tightness in the credit markets continue, future extensions of
our credit facility may contain terms that are less favorable than those of our current credit
facility.

Current market conditions also elevate the concern over our cash deposits, which totaled
approximately $2.3 million at September 30, 2011, but fluctuate throughout the year, and
counterparty risks related to our trade credit. Our cash accounts and deposits with any financial
institution that exceed the amount insured by the Federal Deposit Insurance Corporation are at risk
in the event one of these financial institutions fails. We sell our crude oil, natural gas and NGLs
to a variety of purchasers. Some of these parties are not as creditworthy as we are and may
experience liquidity problems. Non-performance by a trade creditor could result in losses.

Subsequent Events

On October 7, 2011, we announced the retirement of certain of our officers and a Company-wide
reorganization of our operating and administrative functions (the Reorganization). The
Reorganization was approved by the Board of Directors on October 4, 2011. As part of the
Reorganization, the retirement and termination of employment of the affected officers and employees
started during October 2011 and will be completed in full by June 2012.

As part of the Reorganization, we were authorized by the Board of Directors to offer severance
benefits to the affected officers and employees on terms specified by the Board (collectively, the
Severance Program). The estimated total expense of the Severance Program is approximately $2.6
million, which includes approximately $1.8 million in one-time severance payments and approximately
$0.8 million of stock compensation expense related to the acceleration of restricted stock awards.

ITEM 3  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Exposure to market risk is managed and monitored by our senior management. Senior
management approves the overall investment strategy that we employ and has responsibility to ensure
that the investment positions are consistent with that strategy and the level of risk acceptable to
us. The carrying amounts reported in our consolidated balance sheets for cash and cash equivalents,
trade receivables and payables, installment notes and variable rate long-term debt approximate
their fair values.

Interest Rate Sensitivity

We are exposed to changes in interest rates. Changes in interest rates affect the
interest earned on our cash and cash equivalents and the interest rate paid on our borrowings. In
March 2011, we entered into an interest rate swap agreement to manage our cash flow on refinanced
debt. Under the agreement, $50.0 million of our debt is subject to a fixed rate of 2.51%, with a
swap floating rate of 3-month LIBOR, subject to a 2.0% floor.

Our long-term debt as of September 30, 2011, is denominated in U.S. dollars. Our debt has
been issued at variable rates, and as such, interest expense would be impacted by interest rate
changes. The new revolving credit facility entered into March 2011 is not subject to LIBOR floors,
and the impact of 100-basis point increase in LIBOR interest rates would have resulted in an
increase in interest expense of

approximately $1.3 million annually based on the $125.0 million
balance of our revolver as of September 30, 2011. LIBOR rates were less than 100-basis points as of
September 30, 2011, so any decrease in interest rates would have resulted in a nominal decrease in
interest expense under our revolver as of September 30, 2011. The term loan portion of our new
credit facility includes a 2.0% LIBOR floor. The impact of a 100-basis point increase in LIBOR
rates above our 2.0% floor would result in an increase in interest expense under our term loan of
$0.3 million annually based on the $25.0 million balance of our term loan which is not subject to
the interest rate swap as of September 30, 2011. A 100-basis point decrease would have no effect on
interest expense under our term loan until the LIBOR rate exceeds 2.0%.

Commodity Price Risk

Our revenue, profitability and future growth depend substantially on prevailing prices
for oil and natural gas. Prices also affect the amount of cash flow available for capital
expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce
the amount of oil and natural gas that we can economically produce. We currently sell most of our
oil and natural gas production under market price contracts.

During the quarter ended September 30, 2011, Shell Energy North America-US accounted for
$16.7 million, or approximately 69%, of our revenue from the sales of oil and natural gas. No other
purchaser accounted for 10% or more of our oil and natural gas revenue for the quarter ended
September 30, 2011.

To reduce exposure to fluctuations in oil and natural gas prices, to achieve more
predictable cash flow, and as required by our lenders, we periodically utilize various derivative
strategies to manage the price received for a portion of our future oil and natural gas production.
We have not established derivatives in excess of our expected production.

Our open derivative positions at September 30, 2011, consisting of put/call collars,
sold put options, which limit the effectiveness of purchased put options at the low end of the
put/call collars to market prices in excess of the strike price of the put option sold and bare
purchased put options, also called bare floors as they provide a floor price without a
corresponding ceiling, are shown in the following table:

Crude Oil (Bbls)

Natural Gas (Mmbtu)

Collars

Collars

Floors

Ceilings

Put Options Sold

Floors

Ceilings

Bare Floors

Year

Per Day

Price

Per Day

Price

Per Day

Price

Year

Per Day

Price

Per Day

Price

Per Day

Price

Q411

2,150

$

80.00

2,150

$

105.00

-

-

Q411

-

-

-

-

6,973

$

4.17

Q112

2,000

$

80.00

2,000

$

105.00

1,000

$

70.00

Q112

-

-

-

-

6,700

$

4.35

Q212

2,000

$

80.00

2,000

$

105.00

1,000

$

70.00

Q212

5,000

$

4.00

5,000

$

6.00

-

-

Q312

1,900

$

92.63

1,900

$

105.66

1,238

$

70.00

Q312

5,000

$

4.00

5,000

$

6.00

-

-

Q412

1,750

$

92.14

1,750

$

104.83

1,138

$

70.00

Q412

-

-

-

-

-

-

Q113

1,800

$

95.28

1,800

$

101.39

1,450

$

70.00

Q113

-

-

-

-

-

-

Q213

1,650

$

95.00

1,650

$

99.93

1,325

$

70.00

Q213

-

-

-

-

-

-

Q313

1,600

$

95.00

1,600

$

99.94

-

-

Q313

-

-

-

-

-

-

Q413

1,550

$

95.00

1,550

$

99.71

-

-

Q413

-

-

-

-

-

-

Q114

1,600

$

95.00

1,600

$

100.03

1,600

$

70.00

Q114

-

-

-

-

-

-

Q214

1,500

$

95.00

1,500

$

99.13

1,500

$

70.00

Q214

-

-

-

-

-

-

Based on September 30, 2011, NYMEX forward curves of natural gas and crude oil futures
prices, adjusted for volatility by 170 basis points, we would expect to receive future cash
payments of $13.2 million under our natural gas and crude oil derivative arrangements as they
mature. If future prices of natural gas and crude oil were to decline by 10%, we would expect to
receive future cash payments under our natural gas and crude oil derivative arrangements of
$23.5 million, and if future prices were to increase by 10%, we would expect to receive future cash
payments of $2.8 million.

ITEM 4  CONTROLS AND PROCEDURES

Under the supervision and with the participation of our management, including our
principal executive officer and principal financial officer, we evaluated the design and operation
of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the
Securities Exchange Act of 1934, or the Exchange Act) as of September 30, 2011. On the basis of
this review, our management,

including our principal executive officer and principal financial
officer, concluded that our disclosure controls and procedures are designed, and are effective, to
give reasonable assurance that the information required to be disclosed by us in reports that we
file under the Exchange Act is recorded, processed, summarized and reported within the time periods
specified in the rules and forms of the SEC and to ensure that information required to be disclosed
in the reports filed or submitted under the Exchange Act is accumulated and communicated to our
management, including our principal executive officer and principal financial officer, in a manner
that allows timely decisions regarding required disclosure.

We did not effect any change in our internal controls over financial reporting during the
quarter ended September 30, 2011 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.

Forward-Looking Statements

The description of our plans and expectations set forth herein, including expected
capital expenditures and acquisitions, are forward-looking statements made pursuant to the safe
harbor provisions of the Private Securities Litigation Reform Act of 1995. These plans and
expectations involve a number of risks and uncertainties. Important factors that could cause actual
capital expenditures, acquisition activity or our performance to differ materially from the plans
and expectations include, without limitation, our ability to satisfy the financial covenants of our
outstanding debt instruments and to raise additional capital; our ability to manage our business
successfully and to compete effectively in our business against competitors with greater financial,
marketing and other resources; and adverse regulatory changes. Readers are cautioned not to place
undue reliance on these forward-looking statements, which speak only as of the date hereof. We
undertake no obligation to update or revise these forward-looking statements to reflect events or
circumstances after the date hereof including, without limitation, changes in our business strategy
or expected capital expenditures, or to reflect the occurrence of unanticipated events.

PART II  OTHER INFORMATION

ITEM 1  LEGAL PROCEEDINGS

Reference is made to Part I, Item 3, Legal Proceedings, in our annual report on Form
10-K for the year ended December 31, 2010 and Part II, Item 1, Legal Proceedings, in our
quarterly report on Form 10-Q for the quarter ended June 30, 2011, for a discussion of pending
legal proceedings to which we are a party.

ITEM 1A  RISK FACTORS

Reference is made to Part I, Item 1A, Risk Factors, in our annual report on Form 10-K
for the year ended December 31, 2010 and Part II, Item 1A, Risk Factors, in our quarterly report
on form 10-Q for the quarter ended June 30, 2011, for a discussion of the risk factors which could
materially affect our business, financial condition or future results.

Loan Agreement dated November 29,
2007, by and between RAM Energy Resources, Inc., as Borrower, and
Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders.

First Amendment to Loan Agreement
dated November 29, 2007, by and between RAM Energy Resources, Inc.,
as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger
and Administrative Agent, Wells Fargo Foothill, Inc., as the
Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as
the Co-Syndication Agents, and the financial institutions named
therein as the Lenders.

(15)[10.17.1]

10.10.2

Second Amendment to Loan Agreement
dated November 29, 2007, by and between RAM Energy Resources, Inc., as
Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent,
Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG,
New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the
financial institutions named therein as the Lenders.

(16)[10.17.2]

10.10.3

Third Amendment to Loan Agreement
dated November 29, 2010, effective December 3, 2010, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim
Corporate Funding, LLC, as the Arranger and Administrative Agent,
Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG,
New York Branch and CIT Capital USA Inc., as the Co-Syndication
Agents, and the financial institutions named therein as the Lenders.

(20)[10.8.3]

10.11

Description of Compensation Arrangement with G. Les Austin.*

(12)[10.18]

10.11.1

First Amendment to Employment Agreement of G. Les Austin, dated December 30, 2008.*

(13)[10.18.1]

10.11.2

Second Amendment to Employment Agreement of G. Les Austin, dated March 23, 2011.*

First Amendment to Revolving Credit
Agreement dated as of June 10, 2011, by and between RAM Energy Resources, Inc.,
as Borrower, and Sun Trust Bank, as Administrative Agent, Capital One,
N.A., as Syndication Agent, and the financial institutions named therein as the Lenders.

(25) [10.14.1]

10.15

Second Lien Term Loan Agreement
dated March 14, 2011, among RAM Energy Resources, Inc., as Borrower,
Guggenheim Corporate Funding, LLC as Administrative Agent, and the financial institutions named therein as the Lenders.

Furnished with this report. In accordance with Rule 406T of
Regulation S-T, the information in these exhibits shall not be deemed
to be filed for purposes of Section 18 of the Securities Exchange
Act of 1934, as amended, or otherwise subject to liability under that
section, and shall not be incorporated by reference into any
registration statement or other document filed under the Securities
Act of 1933, as amended, except as expressly set forth by specific
reference in such filing.

(1)

Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on May 12, 2006, as the exhibit number indicated in brackets
and incorporated by reference herein.

(2)

Filed as an exhibit to the Registrants Registration Statement on
Form S-1 (SEC File No. 333-113583) as the exhibit number indicated in
brackets and incorporated by reference herein.

(3)

Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on October 26, 2005, as the exhibit number indicated in
brackets and incorporated by reference herein.

(4)

Included as an annex to the Registrants Definitive Proxy Statement
(No. 000-50682), dated April 12, 2006, as the annex letter indicated
in brackets and incorporated by reference herein.

(5)

Filed as an exhibit to the Registrants Current Report on Form 8-K on
October 20, 2006, as the exhibit number indicated in brackets and
incorporated by reference herein.

(6)

Filed as an exhibit to the Registrants Current Report on Form 8-K on
June 5, 2006, as the exhibit number indicated in brackets and
incorporated by reference herein.

(7)

Filed as an exhibit to the Registrants Registration Statement on
Form S-1 (SEC File No. 333-138922) as the exhibit number indicated in
brackets and incorporated by reference herein.

(8)

Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on February 2, 2007, as the exhibit number indicated in
brackets and incorporated by reference herein.

(9)

Filed as an exhibit to Registrants Form 8-K dated November 29, 2007,
as the exhibit number indicated in brackets and incorporated by
reference herein.

(10)

Filed as an exhibit to Registrants Form 8-K dated February 26, 2008,
as the exhibit number indicated in brackets and incorporated by
reference herein.

(11)

Filed as an exhibit to Registrants Definitive Proxy Statement (No.
000-50682) dated April 14, 2008, as the exhibit number indicated in
the brackets and incorporated herein by reference.

(12)

Filed as an exhibit to the Registrants Quarterly Report on Form 10-Q
filed on May 9, 2008, as the exhibit number indicated in brackets and
incorporated by reference herein.

(13)

Filed as an exhibit to Registrants Form 8-K filed January 5, 2009,
as the exhibit number indicated in brackets and incorporated by
reference herein.

(14)

Filed as an exhibit to Registrants Form 8-K filed March 25, 2009, as
the exhibit number indicated in brackets and incorporated by
reference herein.

(15)

Filed as an exhibit to Registrants Annual Report on Form 10-K filed
on March 12, 2009, as the exhibit number indicated in brackets and
incorporated by reference herein.

(16)

Filed as an exhibit to Registrants Form 8-K filed July 2, 2009, as
the exhibit number indicated in brackets and incorporated by
reference herein.

(17)

Filed as an exhibit to Registrants Form 8-K filed March 18, 2010, as
the exhibit number indicated in brackets and incorporated by
reference herein.

Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc., as
Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative
Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York
Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial
institutions named therein as the Lenders.

First Amendment to Loan Agreement dated November 29, 2007, by and between RAM
Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the
Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the
Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as
the Co-Syndication Agents, and the financial institutions named therein as the
Lenders.

(15) [10.17.1]

10.10.2

Second Amendment to Loan Agreement dated November 29, 2007, by and between RAM
Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the
Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the
Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as
the Co-Syndication Agents, and the financial institutions named therein as the
Lenders.

(16) [10.17.2]

10.10.3

Third Amendment to Loan Agreement dated November 29, 2010, effective December 3,
2010, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim
Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo
Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT
Capital USA Inc., as the Co-Syndication Agents, and the financial institutions
named therein as the Lenders.

(20) [10.8.3]

10.11

Description of Compensation Arrangement with G. Les Austin.*

(12) [10.18]

10.11.1

First Amendment to Employment Agreement of G. Les Austin, dated December 30, 2008.*

(13) [10.18.1]

10.11.2

Second Amendment to Employment Agreement of G. Les Austin, dated March 23, 2011.

First Amendment to Revolving Credit Agreement dated as of June 10, 2011, by and
between RAM Energy Resources, Inc., as Borrower, and Sun Trust Bank, as
Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial
institutions named therein as the Lenders.

(25) [10.14.1]

10.15

Second Lien Term Loan Agreement dated March 14, 2011, among RAM Energy Resources,
Inc., as Borrower, Guggenheim Corporate Funding, LLC as Administrative Agent, and
the financial institutions named therein as the Lenders.

Furnished with this report.
In accordance with Rule
406T of Regulation S-T, the
information in these
exhibits shall not be
deemed to be filed for
purposes of Section 18 of
the Securities Exchange Act
of 1934, as amended, or
otherwise subject to
liability under that
section, and shall not be
incorporated by reference
into any registration
statement or other document
filed under the Securities
Act of 1933, as amended,
except as expressly set
forth by specific reference
in such filing.

(1)

Filed as an exhibit to the
Registrants Current Report
on Form 8-K filed on May
12, 2006, as the exhibit
number indicated in
brackets and incorporated
by reference herein.

(2)

Filed as an exhibit to the
Registrants Registration
Statement on Form S-1 (SEC
File No. 333-113583) as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(3)

Filed as an exhibit to the
Registrants Current Report
on Form 8-K filed on
October 26, 2005, as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(4)

Included as an annex to the
Registrants Definitive
Proxy Statement (No.
000-50682), dated April 12,
2006, as the annex letter
indicated in brackets and
incorporated by reference
herein.

(5)

Filed as an exhibit to the
Registrants Current Report
on Form 8-K on October 20,
2006, as the exhibit number
indicated in brackets and
incorporated by reference
herein.

(6)

Filed as an exhibit to the
Registrants Current Report
on Form 8-K on June 5,
2006, as the exhibit number
indicated in brackets and
incorporated by reference
herein.

(7)

Filed as an exhibit to the
Registrants Registration
Statement on Form S-1 (SEC
File No. 333-138922) as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(8)

Filed as an exhibit to the
Registrants Current Report
on Form 8-K filed on
February 2, 2007, as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(9)

Filed as an exhibit to
Registrants Form 8-K dated
November 29, 2007, as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(10)

Filed as an exhibit to
Registrants Form 8-K dated
February 26, 2008, as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(11)

Filed as an exhibit to
Registrants Definitive
Proxy Statement (No.
000-50682) dated April 14,
2008, as the exhibit number
indicated in the brackets
and incorporated herein by
reference.

(12)

Filed as an exhibit to the
Registrants Quarterly
Report on Form 10-Q filed
on May 9, 2008, as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(13)

Filed as an exhibit to
Registrants Form 8-K filed
January 5, 2009, as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(14)

Filed as an exhibit to
Registrants Form 8-K filed
March 25, 2009, as the
exhibit number indicated in
brackets and incorporated
by reference herein.

(15)

Filed as an exhibit to
Registrants Annual Report
on Form 10-K filed on March
12, 2009, as the exhibit
number indicated in
brackets and incorporated
by reference herein.